Fluid streams derived from natural gas reservoirs, petroleum or coal, often contain a significant amount of acid gases, for example carbon dioxide (CO2), hydrogen sulfide (H2S), sulfur dioxide (SO2), carbon disulfide (CS2), hydrogen cyanide (HCN), carbonyl sulfide (COS), or mercaptans as impurities. Said fluid streams may be gas, liquid, or mixtures thereof, for example gases such as natural gas, refinery gas, hydrocarbon gasses from shale pyrolysis, synthesis gas, and the like or liquids such as liquefied petroleum gas (LPG) and natural gas liquids (NGL).
Various compositions and processes for removal of acid gasses are known and described in the literature. It is well-known to treat such fluid streams with amine solutions to remove these acidic gases. The amine usually contacts the acidic gases and the liquids as an aqueous solution containing the amine in an absorber tower with the aqueous amine solution contacting the acidic fluid counter currently.
The most widely used amines are monoethanolamine (MEA) and diethanolamine (DEA) which are most commonly made by reacting ethylene oxide and ammonia. Both amines are irritants to the skin. Ethylene oxide is an irritant to the eyes and skin, and is a suspected human carcinogen; it is also highly flammable, a fire danger and has a high explosive risk. Further, anhydrous ammonia may be fatal in concentrated form, poses a moderate fire risk, and may reach explosive limits in air.
The removal of sulfur compounds from these fluid streams is of particular importance for various reasons. For instance, the level of sulfur compounds in natural gas has to be reduced by suitable processing measures immediately at the source of a natural gas, since the natural gas will customarily also contain a certain fraction of entrained water as well as the above-recited sulfur compounds. In aqueous solution, however, these sulfur compounds are present as acids and have a corrosive effect. To transport natural gas in a pipeline, therefore, predetermined limits must be complied with for the sulfur-containing impurities. In addition, numerous sulfur compounds are malodorous and, with H2S a prime example, extremely toxic even at low concentrations.
Similarly, the CO2 content of hydrocarbonaceous gases, such as natural gas, customarily has to be significantly reduced, since high concentrations of CO2 reduce the calorific value of the gas and may likewise cause corrosion to pipework and fittings.
However, it is often desirable to treat acid gas mixtures containing both CO2 and H2S so as to remove the H2S selectively from the mixture, thereby minimizing removal of the CO2. Selective removal of H2S results in a relatively high H2S/CO2 ratio in the separated acid gas which simplifies the conversion of H2S to elemental sulfur.
The European patent application EP0322924 discloses, for example, that tertiary alkanolamines, especially methyldiethylanolamine (MDEA), are particularly suitable for a selective removal of H2S from gas mixtures containing H2S and CO2. However, in mixtures having a high concentration of CO2, it has been found to be disadvantageous that the effectiveness of the solution for removing H2S is much reduced by an accelerated absorption of CO2.
It is also known to use a liquid absorbent containing a severely hindered amino compound for the selective removal of hydrogen sulfide from normally gaseous mixtures. See, for example, U.S. Pat. No. 4,471,138, the teachings of which are hereby incorporated by reference. However, this method cannot provide for low levels of H2S levels, for example lower than 10 parts per million (ppm).
U.S. Pat. No. 4,618,481, which is incorporated by reference herein in its entirety, discloses the absorption of hydrogen sulfide by the use of an alkaline absorbent composition comprising a severely hindered amine and an amine salt to produce a treated gas having less than 10 ppm hydrogen sulfide. However, this method shows a significant decrease in capacity.
U.S. Pat. No. 7,427,383 discloses contacting gaseous streams containing H2S with an aqueous silicon-containing composition; however, this method is ineffectual in reducing H2S content unless high shear conditions are employed.
U.S. Pat. No. 4,959,086, which is incorporated herein in its entirety, discloses a process for removing H2S from a gas mixture by contacting the gas mixture with a liquid absorbent composition comprising an aminopyridine, such as 4-dimethylaminopyridine. However, said compounds demonstrate limited solubility in water and generally require a suitable solvent such as lower alkane diols, polyols, alkyl ethers, esters, sulfolans, and the like for practical application.
As such, there is a need for a class of compounds, and method to use said compounds, to remove hydrogen sulfide selectively in the presence of carbon dioxide from fluid streams, which does not require specialized equipment, e.g., high shear; is effective over a broad range of carbon dioxide concentrations, and demonstrates an improved solubility in water.